In the offshore oil and gas production industry, there has been a long and unmet need for dealing with a problem known as sustained casing annulus pressure. Sustained casing annulus pressure can be defined as any recorded pressure on casing strings, other than drive or structural strings, that cannot be bled to zero. Causes of sustained casing annulus pressure include leaks in tubing, casing, packers, wellhead packoffs, and poor or failed primary cement jobs.
Controlling casing annulus pressure is a significant problem, especially in the offshore drilling environment. In those areas of the Gulf of Mexico which are federally regulated, the Minerals Management Service guidelines mandate zero pressure above the sea floor at all times, but do allow for certain types of non-compliant approval to maintain production or delay early abandonment. It has been reported that more than 8000 wells and 11,000 casing strings have been identified with sustained casing annulus pressure in the Gulf of Mexico alone. Of these reported cases, approximately 30% of these wells require special departure waivers issued by the Minerals Management Service to maintain production and all require continuous investment in either remediation or monitoring. Further in recent years, enforcement has become more restrictive and several operators have been forced to spend millions of dollars to solve this problem.
Sustained casing annulus pressure can also be a significant safety issue for oil and gas producing wells. In a recent report, approximately 150 Alaskan North Slope wells subject to casing annulus pressure buildup were shut-down by the operator out of safety concerns. This shut-down of considerable production capacity (reportedly about 6 percent of total crude output) was a safety precaution taken in response to the rupture and fire at a well caused by casing annulus pressure buildup.
One reported low cost method of controlling sustained casing annulus pressure is inserting a flexible hose into the restricted annuli of outer casing strings so high density fluids can be effectively displaced. Typically these high density fluids include high density brines specially formulated for injection and displacement of the existing fluids in the casing annulus. This displacement of the existing annulus fluid with a heavier (i.e. higher density) brine provides a simple way for an operator to regain control over sustained casing annulus pressures.
Common difficulties with the above method include inserting the flexible tubing to the desired depth without coiling and effectively displacing the existing casing annulus fluid with the desired heavy brine. Further, it should be appreciated that dilution of the injected fluid and corrosion caused by the high brine concentration are significant concerns. Furthermore, high density brines are expensive and pose additional health, safety and product handling concerns. Further it is known that heavy brines can cause a non-salt containing water based packer fluid to flocculate. This flocculation is reported to not allow the heavy brine to settle to the bottom of the casing string were it is desired. Replacement of the heavy brine solution with high density fluids of suspended solids (such a barite) is generally considered impractical because suspending the solids requires fluids of high viscosity which are not easily injected. Small diameter apertures present in the valves and other flow and pressure control equipment used to place casing annular fluids prevent the use of conventional weighting agents because these materials block and plug the narrow restrictions. Despite the continued efforts in this area, there remains and exists an unmet need for fluids that exhibit a high density and do not exhibit the problems of solids settling or corrosion concerns.